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Flare Measurement "Best Practices" To Comply With National & Provincial Regulations

Prepared by Curtis Gulaga Business Development Manager CB Engineering Ltd. and Brett Light Sr. Facilities Engineer Nexen Canada Limited

1.0

Introduction

There has recently been an increased awareness by oil and gas companies in North America towards emissions monitoring and reduction for both environmental and economical reasons. For years, several countries worldwide have had stringent regulation in place. Regulations were implemented in 1993 relating to the measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities on the Norwegian continental shelf. Inevitably, oil companies operating in the region had to comply to this regulation. Recently, with gas prices soaring, and new government legislation on the horizon, producers, refineries and chemical companies have been looking for a cost effective solution to reduce emissions, and to provide tighter control for both leak detection and mass balance. To tolerate the extreme process conditions often found in a flare line, yet provide accurate measurement to comply with regulators such as the Energy and Utilities Board, the technology of choice is of most importance. Many metering technologies have been tried and tested, and continue to be with little success today. To understand why the results have been dismal, one needs to fully understand the application and the limitations for the various flow-metering technologies available. 2.0 Government Legislation

regards to flaring, and other provinces in Canada are expected to follow suite. The guide will state that measurement will be required for continuous or routine flare and vent sources at conventional oil and gas production and processing facilities where an annual average total flared and vented volumes per facility exceed 500 m3/day. If all solution gas is flared or vented from conventional or heavy oil production facilities, the measured produced gas (less fuel gas use) may be used to report volumes flared or vented. In such situations, specific flare or vent gas meters are not required Solution gas flared and vented from heavy oil or crude bitumen production facilities will also need to be measured where annual average total flared and vented volumes per facility exceeds 0.5 103 m3/day. However, crude bitumen single well batteries within Designated Oil Sands Areas do not require measurement at any volume, as long as suitable estimates are provided in accordance with the requirements. Acid gas flared, either continuously or in emergencies, will need to be metered from gas sweetening systems regardless of volume and Fuel (dilution or purge) gas added to acid gas to meet minimum acid

The Alberta Energy and Utilities Board (EUB) guide 60 will soon be revised with

gas heating value requirements and SO2 ground level concentration guidelines. EUB Guide 60 references EUB Directive 017: Measurement Requirements for Upstream Oil and Gas Operations officially released February 1, 2005. In this directive it specifies the following uncertainties that must be met: · · · · Measurement uncertainty for flare gas must be ± 5 %. Measurement uncertainty for dilution gas must be ± 3 %. Measurement uncertainty for acid gas must be ± 10 %. Accuracy specifications apply to the overall range- ability of the process conditions.

flare gas metering technology is expected to be, but it states that it is, today, the only proven technology to be utilized for these demanding applications. The single requirement of ultrasonic flow meter for flare gas metering is also stated in NORSOK STANDARD I-104, Section 7.1.3.

3.0

Metering Technologies

In Norway, in 1993, regulations relating to measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities were resolved. The regulation was stipulated by the Norwegian Petroleum Directorate (NPD) by virtue of Section 5 of Act of 21 December 1990, relating to CO2 tax in the petroleum activities on the Norwegian continental shelf. The purpose of the regulation was to ensure that the calculation and reporting of CO2 tax was based on accurate measurements. Inevitably, oil companies operating on the Norwegian continental shelf had to conform to this regulation. However, also manufacturers of flare gas metering systems operating in this market were forced to confirm that their instrumentation did comply with these regulations. According to the Norwegian Petroleum Directorate, only three measurement methods were acknowledged for flare gas metering on the Norwegian continental shelf: Ultrasonic measurement Insertion turbines with density measurement / density calculation Thermal mass meters

There are many challenges when trying to measure flare gas, including large pipe diameters, high flow velocities over wide measuring ranges, changing gas composition, low pressure, dirt, wax, CO2, H2S and condensate. For these reasons, traditional technologies such as insertion turbine meters, averaging pitot tubes, and thermal mass meters fall short of being an acceptable solution. Ultrasonic meters have often recorded velocities ranging from 0.02 m/s to 150 m/s in emergency shut down situations. To put that in perspective, 150 m/s is equivalent to 540km/hr. Category 5 hurricanes reach wind speeds of 249 km/hr and have the ability to blow away large trees and destroy complete buildings. To install an insertion turbine or thermal meter, as per the manufacturer's specifications, the probe tip must be inserted in the center third of the pipe, which can range from 6" to 72" diameters. When subject to high velocities, bending and complete failure has taken place. Furthermore, turbines and averaging pitot tubes each have 10:1 turndowns. With stacked transmitters, higher turndown ratios are possible, but nowhere near the required measuring range. Thermal meters have the ability to reach higher turndown ratios when flow calibrated on air or natural gas, but when subject to changing gas compositions, results can fluctuate by as much as 40%. With no self-diagnostics, preventative maintenance programs should be implemented and the sensors extracted quarterly. Point sensors do not have the ability to correct for non-symmetry or swirl in the flowing medium without adequate upstream and downstream pipe diameters. This is generally not an option when working with such large pipe diameters, and therefore performance results will not repeat

However, a new revision states an operational range of flare gas meters up to 100 m/s, which only qualifies the ultrasonic time-of-flight flow meter technology. This is not only a clear indication of what the future

those specified by the manufacturer and obtained under ideal conditions from an accredited flow laboratory. 4.0 Ultrasonic Flow Meters

Figure 1

There are two primary principles for ultrasonic meters, transit time measurement and Doppler effect. If a sound wave is reflected from a moving object, a frequency shift occurs. This frequency shift is the Doppler effect and can also be utilized in flow measurement. However, due to the non-reflective nature of the process conditions at hand, this method is not practical. The transit time gas flow meter is based on the measurement of contra propagating ultrasonic pulses, in which the transit time of the sonic signal is measured along one or more diagonal paths in both the upstream and downstream direction. The flow of gas causes the time for the pulse traveling in the downstream direction to be shorter than for the upstream direction, and this time difference is a measure for the rate of the gas flow as illustrated in figure 1.

Transit time gas ultrasonic meters have been used successfully for years. For single path meters there are two transducers; both receive and transmit ultrasonic pulses. Base design conditions for flowing velocities in gas distribution and transmission pipelines are generally limited to 21m/s due to internal erosion and vibration components. Velocities at this rate can be detected by using a continuous sine wave signal. When measuring flare gas at high velocities, this signal type alone will be drowned by the noise generated from the flowing medium, and subject to the carryalong effect experienced by the ultrasonic ray due to the flowing medium blowing the ultrasonic pulse away from the receiver. Furthermore, most ultrasonic meter designs cannot operate under atmospheric pressure, like that of a flare. Ultrasonic meters designed specifically for flare gas measurement utilize a combination of both a continuous sine wave signal and a variable frequency signal, also known as a "Chirp" signal or cross correlation. This signal is given a unique recognizable form characterized by the pulse duration and the varying signal frequency. At higher velocities, the instrument uses only these Chirp signals. Their unique form makes it possible to recognize them through process noise generated by high gas velocities. The processing of information coming from the transducers and the temperature and pressure transmitters is performed in a flow computer. The computer controls the transmission and detection of the signals to and from the transducers, and performs the critical time measurements. There are multiple outputs configurable for different parameters, and interface is

selectable between RS232C, RS422 and RS485. Meter sizes range from 6" to 72" and are capable of measuring velocities from 0.05 to 100m/s resulting in a 2000:1 turndown. Some manufacturers verifying their capabilities have performed 3rd party testing in wind tunnels capable of achieving extreme velocities with multiple pitot tubes and hot wire anometers. The low-end capabilities are critical for plant leak detection and mass balance while the overall range is required for emission monitoring to comply with provincial and national legislation. Leaks and excess steam delivery to the flare tip are two major causes of loss of product and energy. Reducing them immediately improves the overall efficiency in refinery and chemical plant operation, and payback has been proven with in a matter of months. Accuracies range from 2.5% of measured value up to 25m/s and 5% of measured value from 25-100 m/s, complying with national standards worldwide and already implemented in some provinces of Canada. Wetted sensors that do not protrude into the line create zero pressure drop, and therefore are unaffected by high velocities. Most ultrasonic flow meters are capable of correcting for a non-fully developed flow profile to some degree. This is accomplished in two ways. The first is to use the Reynolds number as a measure of the flow profile, and adjust the measured axial flow velocity according to a function based on the Reynolds number estimated. The second method is to measure the entire cross sectional area of the pipe. Combining the two methods reduces the number of upstream and downstream pipe diameters to only 10 and 5. One should not assume all ultrasonic flow meters are configured this way. Without taking the full cross sectional area into account, the meter behaves similar to that of a point sensor, requiring greater upstream piping diameters to compensate for nonsymmetry in the flow profile. By using Equations 3.1-3.3, the gas volume flow rate can be calculated. By using equation 3.1, the velocity of the flowing medium can be calculated without compensation for

Reynolds number variations. Using live temperature and pressure signals, compressibility factors for standard and operating conditions, Kinematic viscosity, and several algorithms, one can determine a correction factor (K), which in turn provides a velocity of the flowing medium compensated for Reynolds number in equation 3.2. Taking the cross sectional area of the pipe into account, the volumetric flow rate in Sm3/H can be calculated using equation 3.3. Using equation 3.4, the velocity of sound (c) can be calculated on the basis of time of flight measurement. Once the velocity of sound is known, the isentropic index can be found using known equations from thermodynamics relating to isentropic index and the density of the gas with state variables. Empirical formulas have been developed to provide a mass flow rate using transit times to calculate average density and average molecular weight. Eq.3.1 Eq.3.2 Eq.3.3 Eq.3.4

Case Study Nexen was recently faced with implementing a flare metering system at one of their gas plants in Southern Alberta where they had a low-pressure flare and a high pressure flare as outlined in Figure 2. In an effort to comply with the Energy and Utilities board reporting guidelines, Nexen set out to implement a flare metering system that would meet the EUB requirements, and provide a sufficient means for leak detection. One of the challenges they were faced with was the wide range in measurable flow rate, 0.05 to 150 m/s. Second was the risk of failure to intrusive meter designs due to entrained liquids that often appeared as slugs during ESD situations. Third was the limited piping diameters they had to work

with up and downstream of the proposed meter installation. One option was to install the meter in the vertical section of the flare, but this was not practical from a safety perspective due to serviceability 50 feet above ground. The risk of going to flare while a man was working at that elevation was not acceptable. Previously, they had used orifice and strain type gauges but had little success. After careful evaluation, they installed ultrasonic meters designed for flare gas measurement on both the high and low pressure flare lines. With the high pressure flare, there was insufficient pipe length between the knockout and stack, so they

had to install one pair of transducers on each of the two inlet lines prior to the knockout, at the 3 and 9 o'clock positions. The low pressure P&ID was the same with the single transducer pair installed between the KO and flare. All three-meter runs were connected to a single flow computer installed in a non-hazardous area. Expected payback in leak detection alone is expected to be one year.

Figure 2

Conclusion Specific ultrasonic flow meters designed for flare gas measurement have been in use since 1987. Third party testing using wind tunnels to achieve extreme velocities have been conducted and the results have been published. They are proven to be a cost effective solution to reduce emissions, and to provide tighter control for both leak detection and mass balance. UFMs are unaffected by changing gas composition, there are no mechanical moving parts, and self-diagnostics minimize maintenance. When required, the sensors may be extracted from the flare line without shutting down the process for cleaning or calibration checks. They provide turndown ratios in excess of 2000:1, and non-intrusive but wetted sensor designs are not subject to bending or failure, creating zero pressure drop. Most importantly, UFMs designed for flare gas measurement meet or exceed government legislation, and eliminate risk of non-compliance.

References (1) Mylvaganam, K.S. Ultrasonic gas flow meters ­ Novel techniques of transducer orientation and signal processing make high-range ability possible. Measurement & Control, Dec. 1989, pp. 122-127. (2) Norsok Standard. Fiscal Measurement Systems for Hydrocarbon Gas. 1-104. Rev. 2, June 1998. Norwegian Technology Standards Institution (3) Norwegian Petroleum Directorate. Regulations to measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities, August 1993. ISBN 827257-395-4 (4) Alberta Energy and Utilities Board, Directive 017: Measurement Requirements for Upstream Oil and Gas Operations, February 1, 2005. (5) Alberta Energy and Utilities Board, Guide 60, TBA 2005.

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